To evaluate and test underground formations surrounding a borehole it is often desirable to obtain samples of formation fluids for the purpose of characterizing the fluids.
Traditionally in most oilfield applications the hydrocarbon composition, trace elements and physical properties of reservoir fluids are measured at the surface adjacent the well using laboratory style instruments, analysers and equipment which may not necessarily be adapted to field measurements. Samples are also captured in sample receptacles and shipped to remote laboratories for further or more detailed analysis. Tools have been developed that allow samples to be taken from a formation in a logging run, during drilling, or well testing.
Though a fluid analysis on-site and in a continuous mode would offer many advantages generally it has not been possible to perform such analysis in a satisfactory manner before the present invention.
According to existing methods, samples for analysis are typically taken remotely in a sample receptacle, transported to the location where the analysis instrument lies and then the samples are introduced into an analyzer for analysis. A sample receptacle can be: a pressurized vessel such as a sample bottle, or a bladder or a balloon; and many other types well known in the art. Due to the time taken for manual sampling of fluid phases, and the time taken for analysis of these phases, the number of samples captured and the frequency, i.e. time between samples, the analysis of the fluid is limited.
Typically, pressure, temperature and flow rates are reported every 15 minutes during well clean-up and evaluation/production well testing operations. However samples and analysis are typically taken every 3 or more hours. This process is labor intensive and time consuming.
Furthermore during the clean-up and flowing of a well, the composition of the reservoir fluid changes with time. Initially the reservoir fluid will be contaminated with drilling and cushion fluids, perforation and formation debris, and injected chemicals. When the well is clean, hydrocarbon gas, oil and formation water will flow to surface. The quantity of each phase can change as the flow rate is altered and formation pressure is reduced.
It is common practice today during a well test, to take spot samples for analysis at the wellsite. The sampling frequency can vary between 1 to 5 hours. Sampling alone can take 1 hour and 3-4 hours for analysis. These results often do not show the true trend, whereby slugging or other well bore effects often give erratic results. With current methods it is not possible to measure frequently enough to plot the true trend.
In addition, bringing samples to the surface, transporting them to a laboratory, and separating the phase mixtures is time consuming, cost inefficient and provides only post factum-information. In addition fluid samples collected downhole can undergo various reversible and irreversible phase transitions between the point of collection and the point of laboratory analysis as pressure and temperatures change. Furthermore, from the time a sample is collected until it is analysed, there is potential for the sample to be contaminated from air or other external fluids, for the sample to react with the sample receptacle, for components in the sample to react among themselves, for the sample to degrade with time, or for loss of the sample due to leaks.
By directly measuring the properties of the fluid in the flow stream this will reduce impurities mixing with the sample, and the quality of results will be greatly improved as well as removing errors from contamination. In addition there is the Health, Safety and Environmental (HSE) benefit from reducing the exposure of personnel to reservoir fluids and high pressure.
One of the properties of the fluid which may be readily measured in the flow stream is the water liquid ratio (WLR) in a multiphase flow line (oil, water, gas) for a large range of flowing conditions. In particular, this is useful for high gas volume fraction (GVF), where GVF is greater than 95%. Particularly in these conditions, many existing methods for measuring the WLR which work on the flow rate are not successful due to the tiny volume of liquid to be split between the oil and water. Examples of known methods and apparatus for sampling a small sample of representative liquid before measuring the WLT and returning the sample to the line can be found in European patent application number EP1645863 entitled “A sampling apparatus” and PCT International publication number WO2006037565 entitled “A sampling apparatus.” The document EP 1 614 465 describes a microfluidic system for performing fluid analysis having: (a) a submersible housing having a fluid analysis means and a power supply to provide power to said system; and (b) a substrate for receiving a fluid sample, having embedded therein a fluid sample inlet, a reagent inlet, a fluid sample outlet, and a mixing region in fluid communication with the fluid sample inlet, the reagent inlet, and the fluid sample outlet, and wherein the substrate includes a fluid drive means for moving the fluid sample through the substrate, and wherein the substrate interconnects with the housing. At least a portion of the fluid analysis means may be embedded in the substrate.
Further examples of known methods and apparatus for in-line multiphase flow meters which include gas-liquid separation technology and handle very high GVF multiphase flows can be found in United Kingdom patent number GB2447908 and PCT International publication number WO2005031311. In these further examples, however, the samples are taken in isokinetic conditions and this requires a complex control system which is not required in the current example.
The document GB 2417913 describes a microfluidic separator 110 comprising a porous membrane 108 supported by a microsieve. The membrane and sieve are arranged in parallel with the flow 106 of the multiphase mixture and the porous membrane is “wetted” by a portion of the mixture which is transmitted though the pores of the membrane for analysis. The membrane may be oleophobic and be arranged to transmit water based solutions or hydrophobic and arranged to transmit oil based solutions or both oleophobic and hydrophobic and arranged to transmit gases. Pressure across the membrane is maintained below capillary breakthrough values for the non-wetting phase and the flow rate though is significantly less than that passing over the membrane thus reducing problems related to cake build up and fouling. The separator may be integral to or connected to a microfluidic sample manipulation/analysis chip and one or several valves, possibly in conjunction with a micropump, which may be used to maintain the pressure drop below the non-wetting phase breakthrough pressure. Collection channels may also comprise an H-fractal configuration. The main application described relates to the use of the separator in logging while drilling (LWD) or measurement while drilling (MWD) to provide continuous real-time data concerning fluid in a subterranean formation.
The document GB 2 433 273 describes a method for determining a property of formations surrounding an earth borehole being drilled with a drill bit (15) at the end of a drill string, using drilling fluid that flows downward through the drill string, exits through the drill bit, and returns toward the earth's surface in die annulus between the drill string and the periphery of the borehole. The method includes the following steps: obtaining, downhole near the drill bit, a pre-bit sample (211) of the mud in the drill string as it approaches the drill bit; obtaining, downhole near the drill bit, a post-bit sample (212) of the mud in the annulus, entrained with drilled earth formation, after its egression from the drill bit; implementing pre-bit measurements on the pre-bit sample; implementing post-bit measurements on the post-bit sample; and determining a property of the formations from the post-bit measurements and the pre-bit. The measurements may be completed downhole, for example using a mass spectrometer.
The application of the present invention to measure WLR fluid property has the advantage of a small sample of representative liquid from the flow line being used and then being returned to the flow line. This application further overcomes the difficulty in making the WLR measurement itself because of the differences in physical properties of the oil and water in standard flow lines by the measurement made in a very small or mini-channel where the superficial tension maintains both phases at the same speed.